Improved Oil Recovery on the Norwegian
Continental Shelf – an International Perspective
Ørjan Jentoft, Technical Manager Norway OBO
1
September 30, 2010
ExxonMobil in Norway
• First Norwegian license PL001
• Operator of 4 fields
- Ringhorne, Balder, Jotun and Sigyn
• Partner in +20 fields and ~50 licenses
- E.g. Sleipner, Grane, Statfjord, Snorre, Åsgard,
Ormen Lange, Tyrihans
• 2009 production of 410 kboed
~10% of Norwegian production
~10% of ExxonMobil 2009 global production
• 2009 expenditures of 17 GNOK (capex & opex)
- 26 GNOK in taxes
• Participated in around one third of 2007-09
discoveries
• 400 E&P employees
2
Definitions and Value Proposition
Key Elements and Definitions
• IOR: pressure maintenance and improved recovery from
water or HC gas injection
• EOR: improvements to recovery from injection of nonnative fluids (e.g. N2, CO2)
• Both utilize designer wells, completions / stimulation,
artificial lift and digital asset management technologies
Value Proposition
• Displace incremental high value in-situ hydrocarbon with
low value injection fluids
• Maintain or build reservoir pressure to maximize flow rates
from producing wells
• Optimize use of existing and new wells and facilities to
sweep and capture economic incremental HC
• Plan IOR/EOR implementation timing relative to unit costs,
concession terms, secondary zones and satellites
3
Typical Timeline
Improved / Enhanced Oil Recovery
IOR/EOR
Defining the
Prize/Target
Miscible target
Immiscible
target
• Mobile only with strong solvents or
mining
• Mobile if miscible injectant used;
production likely at high Wct/GOR (EOR)
• Un-swept or bypassed oil, attic
oil and edge fault block targets,
further mature floods, optimize
displacement process (IOR)
Remaining
Current
OOIP
Immovable
Produced
4
• EUR at End of Field Life under
current depletion plan and assumed
technical / economic limits
EOR Approach - Combining
Technology with Experience
Proprietary Technology
Unique Reservoir
Simulation Capabilities
Polymer Flood Lab
Mass Transfer
Solvent & Oil
Solvent
Invading Solvent
Bypassed Oil
Miscible Gas
Injection Lab
Unique 25 ft EOR
Core-Flood Lab
• Involved in over a third of industry’s miscible gas projects and more than 40% of the
world’s production from miscible EOR
– Projects include hydrocarbon, nitrogen, and CO2 injection
• Expertise in all commercial EOR processes and a leader in new process development
5
EOR Approach: Understand Enhanced
Oil Recovery Processes at All Scales
Understand Physics
at Rock-Pore Level
Laboratory Studies at
Reservoir Conditions
Flow Modeling
Impact of
Fractures &
Heterogeneities
Field Tests
Enhanced Recovery Plan
• Production Performance
• Development Plans
• Surveillance Needs
• Depletion Strategies
6
ExxonMobil IOR/EOR Experience
Prudhoe Bay:
HC Gas Injection
Athabasca Syncrude:
Bitumen Mining
17 Canadian Fields:
HC Gas Injection
Judy Creek, Wizard Lake,
Pembina, Nisku, Rainbow Lake,
and others
Ruhlermoor,
Georgsdorf:
Steamflood
Pembina:
Polymer Flood
Cold Lake: Cyclic
Steam Stimulation
Snorre, Statfjord, Grane,
Tyrihans: HC Gas Injection
Hawkins:
N2 Gas Injection
Celtic: Solids Stabilized
Emulsions
• Active research on EOR for
light and heavy oils
• Strong focus to maximize
economic recovery
Loudon: Surfactant
Flood
Iron River and Celtic:
Single-Well SAGD
• World-wide experience in
miscible & immiscible gas
injection, chemical, and
heavy oil EOR
Kazakhstan Tengiz Field:
Sour Gas Injection (H2S)
Jay: N2 Gas Injection
5 California Steamflood
Projects
Oso: HC Gas Injection
South Belridge, San Ardo,
and others
Abu Dhabi: Gas Injection
(under evaluation)
Cerro Negro:
Cold Flow
19 West US Projects:
CO2 Gas Injection
Means, Salt Creek, Aneth,
Slaughter, Wasson, and others
Dalia: Polymer Flood
(pilot in progress)
West Yellow Creek:
Polymer Flood
Chad: Polymer Flood
(under evaluation)
Light Oil – Gas Injection (Miscible, Immiscible)
Light Oil – Chemical Processes
South Pass 89:
HC Gas Injection
Heavy Oil – Thermal Processes
Heavy Oil – Polymer Flooding, Cold Flow, and Mining
7
Malaysia:
Gas Injection
(execution)
Understanding HC In-Place and Reservoir
Behavior - Essential to Maximize Recovery
Ringhorne
Jurassic
Ringhorne
West
P - Impedance
S- Impedance
Ty Sand
Vp/Vs
8
Maximizing Recovery Process –
ExxonMobil Best Practice
Uplift Assessment
Unconstrained Opportunities
1.
Double displacement waterflooded fault blocks
2.
Waterflood Reservoir A
3.
Complete development of additional fault blocks
4.
Gas Flood Reservoir A
5.
Water flood Reservoir B
6.
Develop thin oil column
100%
90%
70%
7
60%
50%
40%
30%
Barrier Opportunities
7
Optimize combination drive recovery
1-6
20%
10%
0%
Current
Unconstrained
Breakthrough
Remaining
Field x Uplift Assessment
Unconstrained Opportunities
Unrisked
Opp
Reserves
Recovery Factor
80%
1
2
3
7
5
4
6
Risk Uncertainty
Double displacement waterflooded fault blocks
1
M
M
Waterflood Reservoir A
2
M
H
Complete development of secondary/addnl fault blocks
3
M
H
Gas Flood Reservoir A
4
L
M
Water Flood Reservoir B
5
L
M
Develop thin oil column
6
L
M
Supply Cost
9
Barriers to IOR/EOR
Fram
Rig Rates
Oseberg
• IOR/EOR projects often aim to recover bypassed resource, thin
oil sands, low HC saturation, etc. - may require multiple wells
- Typically smaller accumulations, low per well capture and
delayed buildup makes profitability challenging
- Increased well density and/or new dedicated wells required
Bergen
Shetland
Beryl Area
Jotun
Ringhorne
Grane
Balder
Stavanger
Dagny
Volve
Sleipner
Sigyn
Operating Costs and Efficiency
• Cost challenge for Norwegian oil/gas production
- Offshore staffing terms and levels
- Declining production and aging facilities
FIELD EXAMPLE
300
250
INCOME
200
M$
• Significantly higher rig rates observed in Norwegian North Sea
than UK, results in lower IRR and present value
– Why is Norway not part of a global rig market?
150
100
OPEX W/+4%pa
50
OPEX W/-4%pa
0
1
2
3
4
5
YEARS
6
7
8
9
• Industry must push for more efficiency and cost discipline to
maximize recovery and extend life
- Best Practices and Continuous Improvement
- Standardize and “fit for purpose”
- Utilization of existing infrastructure for new developments to
share/reduce costs
10
Barriers to IOR/EOR
Offshore Technical and Environmental Issues
• Cost of injectant due to sourcing / transport / logistics
• Well constraints such spacing, access, slot availability
• Existing platforms may have space limitations or weight constraints
• Introduction of new fluids may require new facilities or modifications due to processing or corrosion issues;
may also need to extend facilities life vs. original design
• Environmental challenges due to disposal and regulations e.g. water handling, conflict with air emissions vs.
overboard; typically high CO2 intensity per produced bbl
Technology development and R&D
• Dilemma of technology development to tailor new developments AND need for standardization to reduce
costs and development cycle time
• Further technology development and R&D can result in improved recovery
– Subsurface and reservoir understanding
– IOR and EOR activities, pilot strategies
• BUT, need to standardize concepts and development solutions for smaller projects to shorten development
time and reduce costs - however, need to avoid compromising on subsurface understanding
11
Summary
• IOR/EOR projects require significant investment, and typically produce
incremental barrels slowly – profitability is a key challenge
• Understanding the subsurface and IOR/EOR processes is essential to
locating and producing the remaining oil and gas
• Barriers to IOR/EOR in Norway include
- Rig rates
- Operating cost and efficiency
- Technical and environmental issues
- Technology development and R&D
- Access to people and services
• ExxonMobil has strong focus on IOR/EOR opportunities
- Extensive IOR/EOR portfolio and experience
12
Improved Oil Recovery on the Norwegian
Continental Shelf – an International Perspective
Ørjan Jentoft, Technical Manager Norway OBO
13
September 30, 2010